Well apparatus



United State Patent '[56] References Cited UNITED STATES PATENTS 3,368,619 2/ 1968 Postlewaite l66/.6 3,422,895 l/l969 Koonce 166/79 3,444,927 5/1969 Childers et al 166/.5

Primary Examiner-James A. Leppink Atromey- H. Mathews Garland ABSTRACT: A'subsea wellhead system for servicing a plurality of wells having spaced wellheads supported on a submerged platform including a movable latch head selectively connectable with {anyone of the wellheads, and flow conductors conneoted from the latch head through the platform to a remotely located control and service station so that well tools for servicing a selected one of the wells are pumped between the remote station and the wellhead through the flow conductors and the latch head.

Patented Nov. 24, 1970 3,542,125

Sheet 1 of 4 k t INVENTOR. Phillip S. Sizer ATTORNEY Patented Nov. 24, 1970 Sheet INVENTOR. Phillip 8. SIZE! Y wW M ATTORNEY Patntd Nov. 24, 1970 Sheet mmm mmm INVENTOR. Phillip S Sizer A TTOR NEY Patented Nov. 24, 1970 3,542,125

- I She at 4 of 4 INVENTOR. Phillip S. Sizer ATTORNEY equipment and techniques for first drilling the wells in such areas and the subsequent servicing of the wells during their production life. An incentive has thus developed'for the grouping ofwells at least at their; wellheadendsiin relatively small clusters for minimizing costs and operational problems during both the drilling of such wells and'their subsequent production. This incentive has become-even'more important as the search for. oil and gas has extended to waters of substantial depth where, for ex ample, wells may be dr illed intooceam beds lying perhaps at least 1,000 feet below the surface ofthe water.

Accordingly, it is a principle object of'thisinventionto'pro;. vide well apparatus which permits accessto any preselected one of a substantial number of wellsserved by the apparatus.

In accordance with a further objectof the invention,fap paratus of the character described is employed to'service a plurality of wells having wellheads supported on a submerged platform located below the surface'of the water; I v

invention connected with a remotely located surface control and wellservice station; I 1

FIG; v2 is an enlarged fragmentary top plan view of a preferred form of the apparatus of the invention supported on a platform including a plurality of wellheads connected with subsea wells;

FIG. 3 is an enlarged top plan view of the platform and related control and communication fluid flow conduits of the remote control and well-servicing station;

, FIG. 4 is an enlarged fragmentary broken view, partially in section and partially in elevation, of thelatch head and its'sup porting arm of the well-servicing apparatus of the invention;

FIG. 4A is' a further enlarged fragmentary side view, par- I tially in section, of the outer'end portion of the latch head supp'ort boom;

FIG. 5 is anenlarged sectional view taken along the line 5-5 ofFIG. 4; FIG. 6 im still further enlarged broken fragmentary view in v vertical section with portions shown in elevation of one of the platform-supportedwellheads with the latch head locked in place and the inward end of the latch head support arm along with the central well flow conductor associated therewith and portions of the latch head flow conductors and related control It is another object of the invention toprovideapparatus of the character describedhaving movable wellheadmeans for-.-

selectively communicatingwith any one of a plurality of wells and shiftable between such wells responsive to signals communicated from a remote location." v v It is another object of the inventionto provideapp aratus of the character described whichincludes flow conduits extending between .a submerged wellhead platform and a remote:

control station for pumping well servicing tools betwe'en, the remote station and-any selected; one of such wells throughmovable means releasably connectable'with the wellheadof each well in the'system.

It is a further object ofthe inventionto-provide apparatus of the character described which includes a movable latch head connect'able with each of the wellhead sfon-the submerged platform for communicating the conduit means-into the-well connected with the wellhead It is a furtherobject of the invention to provide apparatus of the character described'including a latch head which is mova-- ble around a flow conductor connected from the :surfaceinto" one 'of the platform-supported wellheads without disconnection of the flow conductor or latch head so thatdrilli'ng or servicin g operations may be-carriedout directly from thesurfacein some of the wells while the apparatus of the invention is em ployed for servicing others of the wells.

It is a further object of the invention to provide apparatusof the character describedwhich permits access to -any-selected' one of a plurality of under-sea wells without disconnecting or otherwise interfering withpermanen-t flow conductor connecr tions with each of such wells. t

It is a still further objectof the invention to provide a preferred form of apparatus of the character described which includes a plurality of platform supported wellheads spaced in a circular configurationand a latch. head movable on a rotata-: ble support-arm to each-of the-wellheads'ln accordance-with aform 21 to the-station 35 and also houses the various control still further object of the inventiomone particular embodimerit of the apparatus includes a bundle of flow conduits and control lines connected with the latch head androtatable arm and twistable to a sufficient extent to permit the arm tornove to any desired position of rotation while twisting the entire" bundle of controllines and flow conduits to the extent" required for the desired positio'ning-ofthelatchhead support arm Additional objects-and advantages o f the invention will be readily apparent from reading the'following description of a device constructed in accordance with theinvention and by,-

reference to the accompanying drawingsthereof,wherein:

FIG. 1 is a schematic view in elevation'and partially in sec-.

tion of a system of subsea wells utilizing the apparatus of the fluid .tubings;

FIG.' 7 is a view in section along the line 7 7 of FIG. 6 showing-the ineehanism for rotating the-latch head support arm;

FIG. 8 is an enlarged fragmentary view, partially in vertical section and partially in elevation, of the latch head locked in the upper end of one of the wellheads and particularly showing the hydraulic mechanism for locking the latch head in place;

FIG.'9 is a view in-sectionalong theline 9-9 of FIG. 8; and FIG; 10 is a view in section along the line 10 10 of FIG. 8. Referring to FIG. 1 of the drawings, a well-servicing system embodying the invention-is supported on a submerged platform-21 of a tower 22 having legs 23 driven along their lower end portions into the bottom 24 of a body of water 25. The

. platform supports a plurality of spaced wellheads 30, FIGS. 2, ,4, and-6, each communicatingwith' a well 31 drilled into the ocean bed or bottom24 of the body of water. The wells 3.1 are drilled and completed by generally conventional procedures which may be carried out from a drilling ship 32 floating at the surface 254 of the waters and communicating with the platformZlthrougha conductor pipe 33 which houses the various necessary flow conductors, control lines, and the like, not

shown, necessaryto -provide fluid communication and mechanical couplings to the wells for their drilling and completion. As is well known in the subsea drilling'art the conductor-pipe may include a slip joint, not shown, to accommodate the system to the rise and fall of the drilling ship due both to wave action and changes in tide. The well-servicing and production system 20 supported on the tower 22 is connected by means of a large conductor 34' to a production, servicing-and control station 35 supported on a surface platform '40 of a'second derrick'or tower 41. The conductor 34, as explained in more detail hereinafter, provides a flow passage for produced well fluids'to flowfrom the wellheads on the platfluid and well-servicing flow conduits required for'operation of the well system 201 In accordance with the invention, all produced fluids from the wells 31 flow from their weliheads through'the conductor 34 to the station SSand the various functions performed by the well. system 20 are remotely controlled from the station 35. For'exarnple, the well system permits communication with any selected one of the'wells for pumping well tools into and from thewells' from the control station and the well service system'is shifted between selected wells by remote control from thecontrol station. Further, the novel features of the well'servicing system permit servicing of one or more wells while other-wells are connected with the drilling ship 32 through a conductor 33. I

The general arrangement of the wellheads on the platform 21 is a spaced circular pattern as illustrated in FIG. 2. Referring to the specific details of one of the wellheads and its connection into the conductor 34 as illustrated in FIG. 6, each wellhead 30 is supported on a string of surface casing or conductor pipe 42 which extends from just below the platform 21 into the surface portion of the ocean bed or bottom 24. The lower end of the casing 42 may be connected into a mudline suspension system 43 which comprises tubing and easing hangar components together with the necessary valves for con trolling the tubing and casing annulus flow essentially at the mudline so that the well remains protected in the event of damage to the tubing and casing strings extending from the mudline to the platform 21. Such a mudline suspension system is disclosed and claimed in US. Pat. application Ser. No. 704,855, filed Feb. 12, I968, by Frank H. Taylor and Philip S. Sizer. Somewhat similar mudline equipment is also illustrated at pages 3873--3875 of the Composite Catalog of Oil Field Equipment and Services, 1968-1969, published by World Oil, Houston, Texas. A removable tubing hanger 44 is supported at the platform 21 in the wellhead 30 connected at its lower end with and supporting a pair of tubing strings 45 and which extend to the mudline suspension system for producing well fluids from at least two production zones penetrated by the well and also for providing a complete fluid flow circuit within the well for carrying out certain pump down" well servicing procedures. The tubing hanger 44 is supported within the wellhead on a lower end shoulder surface 51 which engages a matching upwardly facing shoulder surface 52 in the wellhead. The tubing hanger has a pair of spaced vertical flow passages 53 and 54 which communicate with the tubing strings 45 and 50 respectively. A valve 55 is disposed in the flow passages 53 of the tubing hanger for controlling flow through such flow passage. Similarly, a valve is disposed in the flow passage 54 of the tubing hanger. While the valves 55 and 60 are illustrated schematically it is to be understood that these valves may be any suitable form of remotely controlled valve which may be moved between open and closed positions by hydraulic fluid pressure, electrical means, and the like. For example, removable remotely controllable valves of the general type illustrated at pages 3821-3823 of the Composite Catalog of Oil Field Equipment and Services, supra, may be used to serve the functions of the valves 55 and 60. Other valves useful at these locations may be some of the pump down types which are pumped by fluid means into operating position and similarly removed. Such pump down valves may be introduced into the tubing hanger and removed from the hanger through the well servicing apparatus of the invention. General discussions of such techniques and equipment are found at pages 3870-3875 of the Composite Catalog of Oil Field Equipment and Services, supra. Valves of the wireline insertable and removable type may require the use of the drilling ship 32 coupled with the wellhead through the conductor pipe 33.

Each wellhead 30 is connected with the conductor 34 through flow lines 61 and 62 including flow control valves 63 and 64, respectively. The flow line 61 communicates with the flow passage 54 in the tubing hanger through an annular groove 65 and a horizontal flow passage in the tubing hanger. Similarly, the flow line 62 communicates with the other flow passage 53 of the tubing hanger through an annular groove 71 and a horizontal flow passage 72 of the tubing hanger. Seals 73, 74, and 75 are in spaced relationship along the tubing hanger to seal around the hanger within the wellhead above and below the annular grooves 65 and 71 in the hanger. When the valves 55 and 60 are closed, and valves 63 and 64 open, well fluids produced through the tubing strings 45 and 50 flow in the flow lines 61'and 62, respectively, into the conductor 34 where they intermingle and flow to the remote station 35 where they may be stored in tanks, either under water or on the platform, not shown, or may be handled in any other suitable manner such as by a flow line extending along the ocean bed from the platform to shore facilities. Each of the wells on the platform 21 are similarly connected with the flow conductor 34 as illustrated in FIG. 6 so that the combined well fluids from all of the wells connected into the tower 22 are produced and intermingled through the conductor 34.

Of course, if legal and other operating requirements necessitate, individual flow lines could be connected with the various wellheads to prevent such fluid intermingling. The valves 63 and 64 maybe remotely controlled by any suitable means from the control station 35 or they may be manually controlled valves operated by a diver.

The well-servicing system 20 includes a latch head supported from an arm assembly 81 rotatably mounted along its inward end portion on the upper end of the conductor 34 above the-platform 21. The latch head releasably couples into any one of the wellheads 30, provides communication into the wellhead, and is movable by the remotely controlled arm 81 to any one of the wellheads on the platform.

The latch head 80 is insertable into and removable from the upper end of the tubing hanger 44 of each wellhead 30 to provide communication through the tubing hanger with the well tubing strings 45 and 50 through the flow passages 53 and 54 of the tubing hanger. Referring to FIGS. 810, the latch head includes an upper cylindrical body section 82 disposed concentrically within a lower cylindrical body section 83 having a lower end surface 84 supported on an internal upwardly facing shoulder surface 85 of the tubing hanger when the latch head is locked in operating position in the hanger as illustrated in FIGS. 6 and 8. The upper body section is secured with the lower body section by a lock ring 86 inserted through a slot 87 in the lower section into alined annular recesses in the upper and lower sections. The lower body section 83 has a central section 90 of reduced wall thickness around a lower reduced portion 92 of the upper latch head body section and spaced therefrom defining an annular cylinder 93 within the latch head between its outer lower and inner upper sections. The in termediate portion 90 of the lower body section of the latch head is provided with a plurality of circumferentially spaced slots or windows 94 each having outwardly convergent side wall surfaces 94a for retaining a radially expandable and contractible locking dog 95 in the slot. An annular piston is slidably disposed in the annular cylinder 93 for expanding the locking dogs 95 to their outward locking position at which their outer portions are received within an internal annular recess 101 of the tubing hanger 44 for locking the latch head in the upper end of the tubing hanger. The piston 100 has an enlarged upper end or head portion 102 disposed within the enlarged upper portion of the annular cylinder 93 while the reduced wall thickness of the annular piston below the head 102 slides in the reduced lower portion of the annular cylinder behind the locking dogs 95 for expanding the dogs and locking them in the expanded positions. The piston has a downwardly convergent lower end surface 100a which engages an upper end downwardly and inwardly sloping surface 9511 on each dog 95 to cam the dog outwardly as the piston moves downwardly. Suitable seals as illustrated in FIG. 8 are provided in the annular piston and the upper and lower sections of the latch head body above and below the piston head 102 so that the piston head may be forced in both the upward and downward directions by fluid introduced from the station 35 through control line 103 above the piston head and 104 below the piston head. The fluid pumped into the annular cylinder 93 through the control line 103 above the piston head 102 forces the piston downwardly to expand the dogs 95 for locking the latch head in operating position in the wellhead. Reduction of the pressure through the line 103 and pumping of fluid through the line 104 into the cylinder 93 below the piston head forces the piston head upwardly withdrawing its reduced lower wall portion from behind the locking dogs 95 so that they are free to move inwardly to their retracted released positions for withdrawal of the latch head from the wellhead.

The body section 82 of the latch head has spaced vertical flow passages 112 and 113 which communicate with the flow passages 53 and 54, respectively, in the tubing hanger of the wellhead when the latch head is locked in operating position v passages 120 and 121 are provided through the latch head body section 82 opening through identical spaced nipple por-v tions'122, FIG. 8, insertable in sealedrelationship into corresponding control fiuidflow passages, not shown, in the tubing hanger 44 for directing control fluid to'the valves55 and 60 so that the valves are remotely controlled for movement between their open and closed positions after inserting the latch head into the wellhead. The upper end of the tubing hanger 44 has an internal beveled annular surface 123 to guide the latch head into the wellhead so that exact alinement of the latch' head with the vertical bore 124 opening into the tubing hanger is not required to insert the latch head into proper position inth e tubing hanger. v

The latch head 80 is supported for a vertical arcuate movement at the outer end of the arm 81 from an L-shaped boom.

130 controlled by' a hydraulic piston unit 131..The latch head is'suspended from a pair of cables 132 which connect at their lower ends to a pair of lugs 133 threaded into opposite sides of the upper end portion of the latch head body section 82. The upper ends of the cables 132 are secured to a bifurcated or v forked outer end portion 130a of the lever 130comprising identical side panel portions each in the form of a conventional horses head" ofthe type generally'used in sucker-rod type pumps for oil wells. The pair of horse's head portions 130a are spaced apart approximately the diameter ofthe latch head body so that eachcable 132 is secured to a lug 134 engaged in the upper end portion of the horse's head as shown in FIG. 4A. Each horses head. has a continuous arcuate verv tical and lower edge surface 135 engaged by the cable 132 as the boom raisesand lowers the latch head so that the latch head is lifted and lowered along a vertical line during its inserconductors 165 and 170 and 'a plurality of control fluid tubings171 are connected from the latch head into an annular fitting 172 secured through the top plate 81a of the arm 81 tion into and withdrawal fromthewellhead. Thearcuate surv face is formed on a radius line drawn to the axis or center of rotation of a pivot pin supporting the boom 130 from a bracket 141 at the outward end of the arm 81'..The boom portion 13012 is connected at its free end by pin 142 to a bifurcated bracket 143'o n the free end of the piston rod 144 of the,

hydraulic piston unit 131. The piston rod is connected within the cylinder 145 of the piston unit to a piston, not shown, having a stroke of sufficient length to move the latch head lever 130 between thepositions illustrated in the solid and broken line representations of the boomand latch head in FIG. 4 so that the latch head is fully insertable into'a wellhead andis raisable vertically and along an arcuate path to a position which permits rotation of the control arm 81 to move the latch head between wellheads. The cylinder 145 of the 'piston'assembly is connected with control fluid lines and151 for' communication of control fluid with the cylinder at its opposite ends forpum'ping the piston andpiston'rodinwardly and outwardly between end positions forraising and lowering the latch head. The lower 'end of the cylinder is pivotally secured on a bracket 145a to the arm 81 to allow the-piston unit to rock or pivot to 'the extent required for moving the boom portion 1311b between the positions illustrated. The outward end of the latch head control arm 81 is supported for cirand the upper race and supported for rotation in the fixed lower race 162. The fitting 172 is held in position by a clamp ring 173 secured by bolts 174 to the lower race 162 as seen in F163. 6. Upper ball bearings 175 are disposed between the lower face of the clamp ring 173 and an upper shoulder on the fitting 172, while, similarly, lower ball bearing are disposed between a downwardly facing shoulder race on the fitting and an upwardly facing shoulder within the lower race 162 so that the fitting 172 is rotatable relative to the fixed lower race 162 and clamp ring 173 as the arm 81 rotates relative to the conductor 34. Flow conductors 165a and 17% along with control fluid tubings 171a extend from the control station35 through the conductor 34 and are connected into the lower end of the fitting 172 communicating with the corresponding conductors 165 and 170 and the control fluid tubings 171 for communicating the control station with the latch head through the conductorpipe 34. The bundle of flow conductors 165 and 170 and control fluid tubings 171 are of semirigid tubular material so that they are readily supported together in a suitable manner extending in an arc between the .fittin'g 172 and the latch head 80 so that there are no sharp turns particularly in the flow conductors 165 and 170 whereby I well-servicing tools maybe pumped through the flow conductors from the control station into the latch head. External annularseals 182 seal around the fitting 172 within the lower race 162 to prevent leakage from within the conductor pipe 34 upwardly and outwardly around the fitting. It is essential in this particular form of the inventionthat an effective seal be made by the rings 182 since each of the wells in the system produce directly into the-flow conductor pipe 34. The conductors. 165a and 170a and tubes 171a of the bundle are of such extreme length between the fitting 172 and the station 35 in the conductor 34 that they readily twist enough to allow the arm 81 along with the fitting 172 to rotate sufficiently when moving the latch head between wells.

- The latch head support arm 81 is rotated between positions for servicing the various wellsby one preferred form of drive mechanism'illustrated in FIG. 7 secured within the side wall panels 81b and 81c of the arm 81 and engageable with the annular gear teeth 163 and 164 around the lower race 162. A hydraulic piston unit supplied with fluid under pressure by lines'l91 and 192 is secured on the inner face of the side panel 810 of the support arm. A ratchet 193 on the piston rod 194 of the piston unit is engagable with the lower annular gear teeth 164 for moving the control arm in a clockwise direction. A locking latch 195 is pivotally supported in alinement with the upper gear teeth 163 and biased toward the teeth by a spring 200. A hydraulic piston unit 201 supplied by fluid lines 202 and 203 has a head 204 secured on its piston rod for engaging the latch 195 to move the latch from locking contact with the teeth 163 and holding it at an unlocked position. Similarly, a hydraulic piston unit 210 is secured along the inner face of the other .side panel 81b. of the arm 81 and is supplied with hydraulic fluid by control lines 211 and 212. The hydraulic unit 210 has a piston rod 213 supporting a ratchet 214 engagable with the upper ring of gear'teeth 163 for moving the controlarm in a counterclockwise direction as viewed in FIG. 7. A latch 220 is pivotally supported in alinement with the lower row of annular gear teeth 164 and biased toward the teeth by a spring 221a. The latch 220 is movable to an unlocked position dis f gagcd from the gear teeth by a hydraulic piston unit 221 supplied with hydraulic fluid through lines 222 and 223. The piston rod of the piston unit 221 is provided with a head 224 for engaging the latch 220 to move it against the spring 221a on a thrust b earingl59 having an upper race 160supported on tapered roller bearings 161, and a lower race 162 welded as a cap on the upper end of the conductor 34. The lower race 162 has external annular upperteeth 163 and lower teeth 164 for driving the arm 81 along its rotational path. A pair of flow to the release or unlocked position.

The latch head supportarm 81 is rotated on the thrust hearing in a clockwise direction as viewed in FIG. 7 by retracting the ratchet 214 by means of hydraulic fluid introduced through the line 212 into the hydraulic piston 210 to disengage the ratchet ftom the upper gear teeth 163 while the piston rod of the hydraulic piston unit 201 is extended by pumping fluid through the line 203 to pivot the latch 195 out of engagement with the upper gear teeth 163 to release the arm for clockwise movement. The ratchet 193 is then repeatedly extended and retracted engaging the lower teeth 164 forcing the arm 81 clockwise relative to the gear teeth with the latch 220 biased inwardly by its spring 221a snapping from tooth to tooth as the support arm moves relative to the gear teeth thus locking the arm against counterclockwise movement at each tooth engaging position of the ratchet. When the arm is at the desired rotational position, the ratchet 193 is locked in engagement with the teeth 164, the latch 195 is released and the ratchet 214 is extended to engage the upper gear teeth so that the arm is locked against movement in either direction.

When counterclockwise movement of the arm 81 as viewed in FIG. 7 is desired, the latch 220 is moved to an unlocked position against its spring 221a by the head 224 of the piston assembly 221, the ratchet 193 is retracted by means of the piston unit 190, and the ratchet 214 is repeatedly extended and retracted engaging the annular teeth 163 to move the arm 81 in a counterclockwise direction. As the arm rotates the latch 195 snaps against its spring 200 from tooth to tooth so that it remains engaged with the gear teeth 163 and will hold the arm against any tendency to swing clockwise while it is being moved counterclockwise by the ratchet 214. When the arm has been rotated to the desired position at which the latch head is alined with a selected wellhead, the ratchets and latches are locked to hold the arm in position.

The various fluid lines to the ratchet and latch piston units for positioning the arm 81 are included with the bundle of flow conductors and control fluid lines connected through the fitting 172 to the remote production and well-servicing con trol station 35 so that the arm rotating mechanism is remotely operable from the station 35.

It is essential that the rotational position of the arm 81 on the platform 21 relative to the wellheads 30 be indicated at all times, both for the purpose of knowing which well is connected with the latch head when servicing a well and for properly guiding the arm and latch head to any selected one of the wells for connecting into and servicing such well. A preferred form of apparatus for determining the arm position is illustrated schematically in FIGS. 3, 6, and 7. A suitable synchro generator motor system is connected between the arm and the control station including a synchro generator 230 mounted on the arm 81 and coupled with the race 162 and a repeater or synchro motor 231 at the control station 35. The synchro generator is driven by a pinion gear 232 which meshes with external annular gear teeth 233 formed around the lower race 162 between its driving gearteeth 163 and 164. The generator is connected by conductors 234 to the synchro motor 231 which drives a suitable dial indicator representing the positioning of the arm 81. The conductors 234 are secured with the flow conductors 165 and 170 and the control fluid tubes 171 extending from the tower platform 21 through the conductor 34 to the control station.

The arm position indicator system may be any one of a number of known systems adaptable to position indication, generally referred to as synchro systems where ac. power is employed and under the terminology "selsyn systems" where dc. power is used. In general, in such systems the generator, such as the generator 230 in the present system, is moved by the element or component whose position is to be indicated and the movement of the generator is tracked or repeated by the motor, 231 in FIG. 3, so that a remote indication of position is readily available. Suitable systems which may fulfill the desired tracking or indicator function are described and illustrated at pages 139 163 of The Manual Of Electromechanical Devices by Douglas C. Greenwood, McGraw-l-Iill Book Company, 1965.

Where the wellhead platform 21 is within the working depth of divers it will be apparent that the assistance of a diver may be employed for the proper positioning of the latch head and its supporting arm 81. A still further type of available equipment which may be used to properly position the latch head is closed circuit television including a camera with the necessary lights mounted on the support arm and viewing apparatus mounted at the control station 35. Other possible mechanisms for indicating the position of the arm, particularly where a substantial number of wellheads are supported at the platform 21, may include driving gears having teeth equal to or a multiple of the number of wellheads and suitable apparatus for determining which of the teeth are engaged by the ratchets connected with the piston units 190 and 210.

Some degree of inaccuracy of the positioning of the outer end of the arm 81 and the latch head relative to the wellheads may be tolerated depending upon the size of the sloping entry surface 123 at the upper end of the tubing hanger 44 in an wellhead relative to the size of the lower end and its guide surfaces on the latch head. If desired, the upper end of the tubing hanger may be enlarged and provided with a relatively large funnel-shaped guide element which would permit appreciably more latitude in the positioning of the latch head over the wellhead for entry of the latch head into its locked position at the upper end of the tubing hanger.

All of the flow conductors a and a, the control fluid tubings 171a, and the electrical conductors from the synchro generator 230, along with the control fluid tubings to the drive mechanism for the arm 81, extend through the conductor 34 to the platform 40 of the control station 35 where they terminate in various equipment such as pumps, manifolds, instrumentation panels, control valves, liquid tanks, and the like for controlling the functions of the latch head and its support arm and the loading and unloading of the pump down tools introduced into and withdrawn from the wellheads through the latch head. Typical equipment of this nature is schematically illustrated and discussed at pages 38723873 of the Composite Catalog of Oil Field Equipment and Services, supra. The location of as much of the well-servicing and related control equipment as possible on the platform 40 at the control station minimizes the .very expensive and time-consuming procedures of the returning of a drilling ship and related equipment to a well after the well is completed and placed in production The well-servicing system 20 is operated generally in the following manner to gain access to and service any one of the wells connected with the platform 21. After the wells have been drilled and completed by means of the drilling ship 32, and the well-servicing system has been connected in operational relationship between both of the platforms, the typical wellhead at the platform 21 is arranged as shown in FIG. 6, except that the latch head 80 is not locked in the position shown. The valves 55 and 60 of each wellhead are at their closed positions and if the well is producing through either or both of the flow lines 61 and 62, the appropriate valves 63 and 64 are open permitting the produced well fluids to flow from the well into the flow conductor 34 in which they intermingle and flow to such production storage and processing facilities as may be connected with the remote station 35.

During the production of the wells through their wellheads 30, when no well servicing is required, the latch head 80 may be coupled into a wellhead so long as the valves 55 and 60 of the head are closed. The latch head may also be supported, when inactive, either at the position represented by the broken lines in FIG. 4 or at its lower position suspended above the platform between wellheads.

When a particular well is to be serviced with the well-servicing system 20 of the invention, the first step in the servicing procedure is the coupling of the latch head 80 into the upper end of the tubing hanger 44 of the wellhead of the particular well to be serviced. Presuming the desired well to be serviced is one other than the one above which the latch head is supported in FIG. 2, the arm 81 supporting the latch head is rotated in the desired direction by manipulation of the appropriate ratchet 193 or 214 and the locking latch 195 or 220, as previously discussed. The exact position of the arm and thus thev relationfof the latch head to the desiredwellhead is observed at the control station35 on the indicator of the synchro motor 231. The pressure of the control fluids supplied to the arm positioning apparatus is controlled from the station 35 until the latch head is determined to'be above the well in question-During the movement of the latch head between wells, pressure in the line 151 to the piston unit 131 is relieved supplied to the piston unit 131 is adjusted to pivot the boom to lower the latch head into the upper end of the tubing hanger 44 of the wellhead. The pressure is relieved in the control line 103 leading to the latch'head while the fluid pressure is raised in the line 104 connected into thelatch head'below the annular piston head 102. The locking dog control piston 100 is raised to its upper end position'at which the locking dogs 95 are free to move inwardly. The lower end shoulder surface 84 on the latch head engages the upper end 123 of the tubing hanger guiding the latch head into the bore 124; of the hanger. if the latch head is slightly vertically misaligned from the tubing hanger, it is readily guided into place by virtue of the shape of the upper end of the tubing hanger and the lower end of the latch head. As the latch head is lowered it remains in the vertical position moving along a vertical axis line which permits its straightentry into the tubing hanger because of the arcuate edge surfaces 135 along which the cables 132 supporting the latch head are guided as the boom 130 lowers the latch head. Straight entry into the tubing hanger is essential to avoid binding or wedging action between the latch head and the tubing hanger. As the latch head is lowered the beveled lower edge surfaces of the locking dogs 95 engage the-beveled upper end surface 123 of the tubing hanger to cam the locking dogs inwardly to their fully retracted positions since; the annular piston 100 is at its upperposition allowing complete retraction fitting 172 and the corresponding conductors 165and 170 into the well through the wellhead and returned to the control station through the other flow conductor. With this well system arrangement, a multiplicity of well-servicing functions may be performed from the control station 35. For example, the well may be treated by supplying fluids into it through one of the flow conductors while returning fluid to the control station through the other flow conductor. The various techniques carried out with pump down tools may be practiced in the well. A pump down" tool train is inserted at the control station into a manifold, not shown, and by manipulation of the pump-and control apparatus at the control station, the tool of locking dogs.,The latch head moves downwardly due to its own weight and theweight of the related apparatus connected with it including the conduits165 and 170 andthe various control lines. The nipples 112, 114, and 122 at the lower end of the latch head are inserted into the upper ends 'of the corresponding flow passages of the'tubing hanger tothe positions illustrated in FIG. 6. 7

When the latch head is fully inserted, into the well head, as

v shown in FIGS 4, 6, and 8, the fluid pressuresapplied to the annular piston100 through the lines 103'and 10.4 are manipulated to displace the piston downwardly to the lower end position illustrated in FIG. 8 expanding the locking dogs 95'outwardly into the internal annular recessillll of the tubing hanger thereby locking the latch head in-the hanger so that fluid pressure may be applied through the 'latchhead into the wellhead. The pressure within the annular'cylinder 93 above the'annular. piston locking the dogs 95 outwardlymay be relieved as the pistonwillremain at its lower end position holding the locking dogs expanded during-the servicing of the well through thelatch head. The valves 63 and 64 are closed to isolate the wellhead from-the conductor 34 duringthe servicing of the well. 1 I

Pressures are then applied in the control fluid conducted to the wellhead throughthe pair of the lines 171 connected into theflow passages 120 and 121 of the latch head-to open the valves and in the tubing hanger so that the flow conductors 165 and 170 may communicate through the wellhead with the tubing strings 45 and 50 supported from the tubing hanger. The tubing strings 45 and 50 are interconnected within the well by suitable crossover apparatus as shown at page 3871 of the Composite Catalog of Oil Field Equipment and Service, supra. Fluids may now be circulated from the control station 35 through one of the flow conductors 165a and 1700, and the train is displaced through one of the flow conductors 165a or 170a with fluid returns passing through the other of the flow conductors from the well back to the control station. The tool train is pumped through the flow conductor within the con ductor 34, through the looped configuration of the flow conductors running from the fitting 172 to the latch head, through the latch head and the tubing hanger 44 into the well and downwardly to the desired location within the well. In accordance with known pump down" procedures, the well tool and the tool train may be returned along the same route to the control station 35 from the well.

When the desired well-servicing operation has been completed the latch head may be released from the particular well serviced and moved to another well requiring similar well servicing. After the well tools have been retrieved from the well and returned to the control station 35, the valves 55 and 6 0 in the tubing hanger are closed by adjustment of the fluid pressure in the lines 171 leading to the valves; and if the well is to be put back on production, its valves 63 and 64 are opened 7 to redirect the well fluids into the flow conductor 34. The pressure in the lines 103 and 184 are adjusted to lift the annular locking piston to its upper end position raising the piston skirt from behind the locking dogs 95 so that they may becontracted inwardly to release the latch head from the tubing hanger. The pressure is adjusted in the piston unit 131 through the lines and 151 to retract the piston rod 144 raising the latch head to the broken-line position illustrated in FlG. 4. As. the latch head is'lifted, the engagement of the beveled upper outer surfaces of the locking dogs 95 acting against the upper surface of the annular groove 101 cams the locking dogs inwardly to their release positions freeing the latch head from the tubing hanger. The latch headis then fully withdrawn from the wellhead and lifted upwardly and in-.

rotated either clockwise or counterclockwise to the next well to be serviced. The arm is moved in the direction which requires the least travel distance to reach the well to be serviced. A particularly advantageous feature of the well-servicing system 20 is that the latch head is movable at its raised position to any other wellhead without interference with a conductor which may be connected with an intervening well for drilling or reworking the well. For example, the drilling ship 32 may be coupled by the conductor 33 with a wellhead on the platform 21 thereby providing a vertical, tubular conduit on the upper end ofthe wellhead which is bypassed by the raised latch head due to its upward and inward location for moving the latch headto wells on eitherside of the connected conductor 33. In'rotating the arm 81 between wells, the conductors a and a along with the control fluid tubes 171a and any other conduits, power conductors, and the like included in the bundle extending between the fitting 172 through the conductor 34 to the control station 35, are rotated with the arm and thus twisted to the degree that the arm is rotated. It is therefore desirable that the arm be rotated no more than one revolution to minimize the twisting of the various conductors in the conductor 34. Preferably, a suitable stop, not shown, is secured on the platform 21 to prevent the movement of the arm 81 more than 360. Obviously, when such a stop is used, it may occasionally be necessary to move the arm a substantial distance to travel between nearby wells on opposite sides of the stop. Such inconvenience, however, is preferred to excessive twisting of the conduits within the conductor 34 which may damage them requiring substantial time and cost for repairs.

One form of well device which may be used in "pump down" procedures for moving a well tool from the control station through the latch head into the well to which the latch head is connected and returned to the control station is a pumpable seal device shown in U.S. Pat. No. 3,318,605, issued May 9, l967 to Norman F. Brown. One or more of the seal units shown in the patent are coupled with a well tool for pumping the well tool along the desired flow passages such as the conductor 165 or 170 responsive to fluid pressure applied to the device from the control station. A tool which may be used in conjunction with a pumpable seal unit as shown by Brown is a fluid pressure actuated operator tool shown in U.S. Pat. No. 3,378,080, issued Apr. 16, 1968 to John V. Fredd.

-The tool shown in the Fredd patent may be used in pump down" procedures for both installing well devices in and removing well devices from a landing nipple connected in a flow conduit such as the tubing 45 or 50 in one of the wells 30 in the system of the present invention. A system of gas lift valves adapted to be installed and removed by a pump down system which is compatible with the present system of invention such that the valves could be installed in any one of the wells, if properly equipped, from the remote control station is illustrated and described in U.S. Pat. No. 3,334,690, issued Aug. 8, 1967 to H. U. Garrett. Other available forms of tools and techniques for remote tool installation and well-servicing are available.

Numerous modifications will be apparent in various subassemblies of the well-servicing system of the invention. For example, the arm 81 may be driven around the platform in its rotational path by the supporting wheel 152 on its track 155. Such an arrangement would include a driving motor connected with the shaft 153 of the wheel and to achieve more positive driving action a rack and pinion arrangement may be provided by teeth formed along the top surface of the rail 155 with meshing peripheral teeth in the surface of the wheel 152. Another form of apparatus for rotating the arm 81 may include a gear and pinion arrangement between the inward end of the arm substantially in the location of the apparatus illustrated in FIG. 7 providing the annular side surface of the lower race 162 with annular gear teeth similar to those illustrated which mesh with one or more driving pinion gears secured with the arm whereby the rotation of the pinion gears drive the arm relative to the fixed annular gear.

While the remote control station 35 is shown as a fixed tower and it is suggested that such a station may similarly be located on land, it will be recognized that a still further form of control station for remote communication with the wells through the latch head is a floating type station carrying facilities for control of the latch head and the pumping of tools to and from the wells. Such a station is buoyantly supported either at the surface or at a near surface depth below shipping and lanes and wave action but reachable by surface supported means such as a ship. 1n the event of use of a floating control station it may be preferred that the production facilities connected with the wells be independent of the control station such as by extension of production flow lines to ocean bottom gathering facilities or along the ocean bottom to the shore with the lines communicating from the control station to the latch head extending through the water or along the bottom independently of the production line conductors.

The service lines or conduits 165 and 170 connected into the latch head have been discussed principally in terms of their use in servicing the wells in the system by procedures including pump down techniques and the flowing of well-treating fluids to and from the wells in the conduits. Other functions which may be performed by the well system of the invention include production tests on the wells. Such tests include the flowing of the well fluids or products from the wells to the control station for analyzing the character of fluids present in the earth structures surrounding the wells. Since such production tests require flowing the well fluids from the formations through the well-servicing conduits, it is possible that sand, paraffin, and other foreign materials may damage or clog one or more of the lines which could impair the system for further well treatment and may necessitate shutting down the primary functions of the system until the lines have been cleared or repaired. A further problem inherent in considering the availability of the system for production testing is that the servicing of a well by pump down methods may require from 1 to 3 days which would thus preclude the availability of the equipment during such period for production testing. In order to overcome both the problems of equipment availability and possible damage to the system by production testing, it may be desired that duplicate components of the system be provided to permit simultaneous servicing by pump-down methods and production testing, such procedures, of course, being carried out in different wells in the system at the same time. For example, duplicate servicing conduits corresponding to the conduits and along with a duplicate latch head 80 may be included in the system, the two latch heads being supported in side-by-side relationship at the end of the arm 81. This arrangement would make available one flow system for well testing and a separate flow system for pump-down procedures, though it would be evident that by virtue of their support from the single arm 81 they would not be available for simultaneous operation. The problem of simultaneous operation, however, may be solved by utilizing such duplicate flow conduits and latch heads along with a duplicate arm 81 supported in a stacked relationship with the arm illustrated. The use of duplicate arms requires placing the arms at different levels or elevations along a common axis of rotation with the central bearings and related components being stacked on the conduit 34 in the general arrangement shown in FIG. 6. The use of duplicate arms would also require duplicate control equipment and related apparatus so that each arm is operable independently of the other, The bundle of conduits and control fluid tubes for each of the arms would be positioned offcenter which is easily accomplished due to their flexibility and thus would permit them to be readily turned or twisted to the extent necessary to reach any one of the wells in the system with the arm. Such duplicate equipment has the further advantage of providing an available spare in the event of the failure of one of the arms which, as a result, would provide substantial savings in both time and money in the event of equipment failure.

It will be evident from the foregoing description that a new and improved system for servicing a plurality of wells located particularly at under water sites from a remotely located central service and control station has been described and illustrated. It will be evident that the well system includes a latch head or flow coupling adapted to be releasably connected into any one of a plurality of wellheads supported on a submerged platform for selectively communicating with any one of the wellheads thereby providing controlled fluid flow from the remote station into each such well head to permit well-servicing operations to be carried out in each well including introducing and retrieving pumpable well tools from the remote station. It will be further evident that well-servicing operations may be carried out within one well from the remote station while drilling or workover operations are being performed in one or more of the other wells in the system served by the apparatus of the invention from other facilities such as a ship located above the wellhead platform. The control of the various functions of the well apparatus is effected from the remote station including termination of production from a well, servicing the well, and returning the well to production status.

The foregoing description of the invention is explanatory only and changes in the details of the construction illustrated may be made by those skilled in the art within the scope of the appended claims without departing from the spirit of the invention.

I claim:

1. A system for communicating with any selected one of a plurality of wells having wellheads arranged in a predeterminedgeometiicril pattern comprising: flow coupling means connectable for communication with any one of said wellheads; means for supporting said flow coupling means for movement along a defined path of said predetermined geometrical pattern between said wellheads; and means from a remote location providing fluid communication with said flow coupling means.

2 A systemas defined in claim 1 wherein said means for communication with saidflow coupling means is adapted to pumping well tools into each of said wells from said remote location and returning said tools to said remote location.

3. A system as defined'in claim 2 including means at said remote location for-controlling the movement of said flow coupling meanswith respect to said wells for selectively connecting said coupling means with any one of said wells.

4. A system as defined in claim 3 wherein said wells have submerged wellheads.

5. A well system as defined in claim -4 wherein each of said wellheads is provided with valve means remotely controllable from said remote location for controlling communication from said flow coupling means through each said wellhead into the well connected thereto and into production fluid flow means from each of said wells.

6. A well system wherein fluid communication is provided from a control station to any selected one of a plurality of wells comprising: a wellhead connected with each of said wells; the wellheads for said wells being disposed in a predetermined geometrical pattern; at least one tubing string supported in each wellfrom the wellhead connected thereto; at least one production fluid flow conductor connected with each wellhead; valve means ineach wellhead for directing well fluids from the tubing string supported from said wellhead into the production fluid flow conductor connected with said wellhead; a flow coupling supported for movement relative to the wellheads and releasably lockable with each of the wellheads, said flow coupling having a flow passage communicatable through each wellhead with the tubing string connected thereto when said coupling is secured with the wellhead; means for supporting said flow coupling for movement along said geometrical pattern of said wellheads from anyone of said wellheads to any other one of said wellheads; a control station spaced from said wellheads; a well-servicing flow conductor extending from said control station to said flow coupling for pumping well tools between said control station and any one of the wells coupled with said flow coupling; and control means at said control station connected with said flow coupling and each of saidfwellh'eads for controlling said valve means of said wellhead, for connecting said flow coupling with and releasing said coupling from each of said wellheads, and for actuating said means for supporting and moving said flow coupling between said wellheads.

7. A well system as defined in claim 6 wherein said wellheads are supported at anunderwater location. 7

8. A system as defined in claim 7whereiri said control station is supported at water level.

9. A system as defined in claim 7 wherein said control tion is on a fixed platform.

10. A well system as defined in claim 7 wherein saidcontrol station is floating. I

11 A well system as defined in claim 7 wherein a production fluidflow conductor is connected from said control station to said wellheads-for flow of well'fluid'sto saidcontrol station and for housing said well-servicing flow conductor and control conductors extendingto said wellheads and said flow coupling from said control station.

12. A well system as defined in claim 6 wherein said flow coupling means is movable'from one wellhead to another wellhead around an intervening wellhead while saidintervening wellhead is connected with a conductor pipe for servicing the well connected thereto independent of said flow coupling.

13. A well system for selectively communicating with any one of a plurality of wells from a remote control station for pumping well tools into and retrieving said well tools from any staone of said wells from said control station comprising: a plurality of wellheads supported at an underwater production platform in a substantially circular pattern; each of said wellheads supporting at least one tubing string in the well connected with said wellhead; a production fluid flow conductor connected with each wellhead communicating with the tubing string connected thereto; valve means in each said production fluid flow conductor for controlling the flow of well fluids from said wellhead through said flow conductor; valve means in each said wellhead for controlling flow through said wellhead to the tubing string connected thereto and for diverting well fluid flow through said wellhead into the production fluid control station; a flow conducting latch head releasably connectable into each of said wellheads and movable between said wellheads along said submerged platform to provide fluid communication through each of said wellheads into the tubing string supported therefrom; support arm means rotatably supported on said submerged platform connected at an outer end portion with said latch head for movably supporting said latch head for movement in a circular path between said wellheads; means rotatably supporting the inward end of said control arm on said platform; means for rotating said arm for moving said latch head between saidwellheads; means connecting said outer end portion of said arm and said latch head including means for raising and lowering said latch head relative to each of said wellheads for inserting said latch head into and withdrawing said latch head from each of said wellheads; latch means included in said latch head for releasably connecting said latch head with each of said wellheads; a flow conductor connected with said latch head extending to said remote control station for conducting well tools between said control station and said latch head whereby said tools are pumped from said control station through said latch head and each said wellhead into the tubing string of each of said wells and pumped from said tubing string back through said wellhead and said latch head to said remote control station; control means at said control station connected with each said wellhead, said latch head, and said means supporting said latch head and said arm for controlling the functions of said arm and said latch head and the valve in each said well head and indicating the position of said arm whereby said latch head is directed to any selected one of said wellheads from said remote control station.

14. A well system as defined in claim 13 wherein said means for rotating said arm is positioned at the inward end of said arm.

15. A well system as defined in claim 13 wherein said means for rotating said arm is located at and coupled with the outer end portion'of said arm.

16. A well system as defined in claim 13 including at least two tubing strings supported in each of said wells from the wellhead connected thereto and at least two well-servicing fluid'flow conductors connected between said latch head and said control station whereby fluid pumped from said control station through one of said conductors and said latch head into any one of said wells is returned from said well through said latch head to said control station in the other of said flow conductors.

17. A well system for communicating with a plurality of underwater wells for servicing the wells from a remote control station includin'gpumping well tools into and out of the wells from the control station comprising: an underwater work platform; a plurality of wellheads supported at said underwater platform, each said wellhead being connected by a conductor pipe to a well drilled into the bottom of the water; a tubing hanger supported in each said wellhead; a pair of tubing strings connected with each tubing hanger extending through said conductor pipe into the well communicating therewith; each said tubing hanger having flow passage means communicating with the tubing strings connected thereto; valve means in each said tubing hanger associated with said flow passage means in said hanger for controlling fluid flow into and from each said tubing string connected with said tubing hanger, said valve means being adapted to be remotely controlled; a control station spaced from said underwater platform; a flow conductor connected from said underwater platform to said control station; a pair of flow lines connected between each of said wellheads and said flow conductor communicating through the tubing hanger of the wellhead connected thereto into the tubing strings connected with said tubing hanger; valve means in each flow line between each wellhead and said flow conductor to said control station for controlling well fluid flow from each wellhead and for isolating each wellhead from said flow conductor; said wellheads being supported at said underwater platform in a substantially circular pattern, each of said wellheads opening upwardly whereby said wellhead is accessible from above said platform; support arm means rotatably mounted above said underwater platform substantially at the center of said well pattern and having an outward end extending toward said wellheads; means connected with said arm for rotating said arm on said platform for positioning the outward end of said arm in alinement with any one of said wellheads; conductor means extending from said rotating means for said arm to said control station for remotely controlling the rotation of said arm from said control station including means for indicating the rotational position of said arm at said control station; a latch head flow coupling supported at the outward end of said arm for movement relative to the wellhead alined with the end of said arm whereby said latch head is moved into and coupled with said wellhead and when uncoupled is moved upwardly and inwardly relative thereto whereby said latch head is movable to bypass any one of said wellheads in said pattern coupled with other facilities for well servicing independently of said latch head; means connected between said arm and said latch head for moving said latch head relative to said wellheads; latch means in said latch head for releasably locking said latch head in any one of said wellheads; conductor means from said control station to said latch head for controlling the position of said latch head and controlling said latch neaafir said latch head from said control station; said latch head being provided with flow passage means for fluid communication through a well hanger into the tubing strings in a well connected with said well hanger for servicing said well through said latch head and said tubing strings including pumping well tools into and out of said tubing strings through said latch head; said latch head having flow passage means communicating with said valve means of the tubing hanger of a wellhead coupled with said latch head for communicating control fluid through said latch head to said valve means whereby said valve means of said tubing hanger is remotely controlled through said latch head; conductor means extending from said latch head to said remote station for controlling said valve means of each tubing hanger coupled with said latch head; a pair of well-servicing flow conductors connected from said control station to said latch head for directing well servicing fluids and well tools through said latch head and the tubing hanger of a wellhead coupled thereto into the tubing strings of the well communicating with the wellhead and returning well servicing fluid and well tools from said well to said control station through said wellhead and said latch head, said pair of flow conductors extending through the inward end of said control arm and through said flow conductor to said control station for directing well servicing fluids and tools from said control station to and from a well connected with saidlatch head; and means at said control station for pumping well servicing fluids and well tools to and from said latch head from said control station.

18. A well system as defined in claim 17 wherein said control station is supported on a platform mounted at a location above the surface of the water spaced from said underwater platform.

19. A well-servicing system as defined in claim 17 wherein said flow conductor from said control station to said underwater platform extends above said underwater platform and said arm is rotatably mounted at the inward end thereof on said flow conductor above said underwater platform.

20. A well-servicing system as defined in claim 19 including a plurality of said latch heads and said conductor means and said well-servicing flow conductors connected with each of said latch heads providing duplicate systems for servicing and testing wells from said control station. 

